Thermal Modulated Vibrating Sensing Module for Gas Molecular Weight Detection

ABSTRACT

A downhole formation fluid identification sensing module for measuring averaged gas molecular weight of wellbore formation fluid acquires simultaneous temperature, pressure, and density measurements. The sensing module includes two venturi-type gas sensors that both contain vibrating tubes. During operation, formation fluid flows through the vibrating tubes whereby resonant frequency measurements are acquired simultaneously with temperature and pressure measurements. Each measurement is then utilized to determine the gas molecular weight of the dry, wet or saturated formation fluid.

FIELD OF THE DISCLOSURE

The present disclosure generally relates to the identification ofwellbore formation fluids and, more particularly, to averaged gasmolecular weight detection with a thermal modulated vibrating sensingmodule, and related methods utilized for in-situ identification ofwellbore formation gas fluids.

BACKGROUND

Averaged gas molecular weight (MW) is closely related to the hydrocarboncomposition of wellbore formation fluid from a hydrocarbon gas reservoirand to the pressure-temperature diagram of a multi-component system witha specific overall composition. As understood in the art, pressure andtemperature can alter gas density, and the measured formation fluiddensity can vary significantly from dry, wet or saturated gases.However, different from the temperature and pressure dependent density,average gas molecular weight of a hydrocarbon gas mixture will be thesame if the reservoir composition is kept constant, regardless of thetemperature and pressure variations. The averaged gas molecular weightvariation may provide a direct correlation to formation gas fluidcomposition and properties, which is normally obtained only by offlinegas chromatography analysis.

Gas molecular weight detection is a particularly important concept inthe field of flow measurement, as the varying densities of theconstituent material may present a significant problem in natural gasproduction. The natural gas is a mixture of hydrocarbon compounds,dominated by C1-C4, with quantities of various non-hydrocarbons such asN₂ and H₂. However, extra small quantities of C5+ may also exist in theliquid phase. The amount of hydrocarbons present in the liquid phase ofthe wet gas extracted depends on the reservoir temperature and pressureconditions, which change over time as the gas and liquid are removed.

Changes in the liquid and gas contents also occur when a wet gas istransported from a reservoir at high temperature and pressure to thesurface where it experiences a transition from high temperature andpressure downhole condition to a lower surface temperature and pressure.The presence and changeability of this wet gas can cause problems anderrors in the ability to accurately meter the gas phase flowrate.

To measure gas molecular weight, a conventional laboratory method is touse either gas chromatography (GC) or gas chromatography (GC) and massspectroscopy (MS) combined GC-MS instrument. The measured hydrocarbongas molecular weight could provide a direct correlation with gasreservoir composition, which is normally obtained only by offline gaschromatography analysis. However, one of the inherent technical barriersis the use of the long capillary-like column based isothermal gasseparation retention time analysis. The other challenge is instrumentoperation under high temperature and pressure conditions that vary withdepth of the downhole. To date, no technical breakthrough has been madein the area of downhole gas molecular weight measurement in downholeconditions for reservoir composition analysis and variation trendmonitoring.

Therefore, there is a need in the art to provide an in-situidentification of a wellbore formation fluid composition and properties.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is block diagrammatical illustration of a thermal modulatedvibrating tubing based gas molecular weight sensing module according tocertain illustrative embodiments of the present disclosure;

FIG. 1B is an exploded view of a single gas sensor package, according tocertain illustrative embodiments of the present disclosure;

FIGS. 2A and 2B are alternative illustrative embodiments of gas sensingmodule in which two gas sensors are arranged in series configuration(FIG. 2A) and parallel configuration (FIG. 2B);

FIGS. 3A and 3B are plots showing hydrocarbon boiling points andmolecular weight as a function of the carbon number, respectively;

FIG. 4 is a pressure-temperature phase diagram that is used for fluidphase control, according to an illustrative method of the presentdisclosure;

FIG. 5 is a diagram illustrating the pressure-temperature phase envelopunder three different gas molecular weights, according to anillustrative method of the present disclosure; and

FIG. 6 illustrates an embodiment of the present disclosure whereby a gasmolecular weight sensing module is utilized in a wireline application.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Illustrative embodiments and related methodologies of the presentdisclosure are described below as they might be employed for in-situwellbore formation fluid composition analysis using a thermal modulatedvibrating sensing module. In the interest of clarity, not all featuresof an actual implementation or methodology are described in thisspecification. It will of course be appreciated that in the developmentof any such actual embodiment, numerous implementation-specificdecisions must be made to achieve the developers' specific goals, suchas compliance with system-related and business-related constraints,which will vary from one implementation to another. Moreover, it will beappreciated that such a development effort might be complex andtime-consuming, but would nevertheless be a routine undertaking forthose of ordinary skill in the art having the benefit of thisdisclosure. Further aspects and advantages of the various embodimentsand related methodologies of the disclosure will become apparent fromconsideration of the following description and drawings.

As described herein, embodiments of the present disclosure are directedto a thermal modulated vibrating sensing module that can be used tomeasure gas molecular weight from wellbore formation fluids, which isthen correlated to gas composition. In a generalized embodiment of thepresent disclosure, the sensing module includes a pair of gas sensors,each comprising a vibrating tube having a mechanism thereon forvibrational excitation and signal acquisition. Each gas sensor includesa thermal modulated hollow tube body having a venturi inlet and outletto regulate fluid flow uniformity. The vibrating tube is coupled betweenthe venturi inlet and outlet. Pressure and temperature sensors arepositioned along the sensing module to provide temperature and pressurecompensated vibrational measurements from the resonant frequency of thevibrating tube. The sensing module may be utilized as a standalonedevice for gas production monitoring, or as part of a downhole assemblysuch as, for example, a sampling tool deployed along a wireline ordrilling assembly for identifying formation fluid composition (such asgas, oil, water or their mixtures). In addition, in certain embodiments,the averaged gas molecular weight could be an indicator of the reservoircomposition.

During formation fluid production operations of the generalizedembodiment, wellbore formation fluid flows into the sensing module andto the first and second gas sensors (also referred to herein as gassensor packages), which are operated under temperatures T₁ and T₂,respectively. As the formation fluid flows through the vibrating tubes,the resonant frequencies of the hollow tubes are simultaneously measuredat two different temperature operating modes, and each gas sensorpackage is kept in an isothermal status. These vibrational measurementsinclude the resonant frequencies of the vibrating tubes as the formationfluid flows through (for gas density determination), in addition to thetemperature and pressure measurements of each gas sensor. Thedifferential pressure measurements across the sensing module are thenutilized to determine the gas molecular weight of the formation fluid.

Embodiments of the present disclosure are useful to analyze a number ofdifferent formation fluid compositions. In one embodiment, the sensingmodule may be used for in-situ dry gas well analysis. In anotherembodiment, the sensing module can be used for wet gas analysis, wherethe small quantity of formation liquid may coexist with the gas. In athird embodiment, the gas sensing module may be used for saturated gasanalysis, where gas can separate from the crude oil in the formationfluid when pressure is above the bubble point. Accordingly, the use ofvarious embodiments of the present disclosure provided are to enhancesampling tool abilities for in-situ averaged gas molecular weightmeasurements of dry, wet, and saturated hydrocarbon gas reservoirs.

As will be understood by those ordinarily skilled in the art having thebenefit of this disclosure, wellbore fluid is a mixture of varioushydrocarbons, and their averaged molecular weight can be obtained byfirst measuring each individual gas composition, then, then determiningeach gas composition's mole percentage or weight percentage.Traditionally, this is done in a laboratory condition using a gaschromatography technique. However, embodiments of the present disclosureprovide a sensing module discussed that directly measures averaged gasmolecular weight without the need to identify each gas composition andits percentage in total volume.

As will be understood by those ordinarily skilled in the art having thebenefit of this disclosure, average gas molecular weight is closelyrelated to the hydrocarbon composition of wellbore formation fluid froma hydrocarbon gas reservoir, in addition to being closely related to thepressure-volume-temperature (“PVT”) diagram or equation of the state(“EOS”) of a multi-component gas mixture reservoir with a specificoverall composition and averaged molecular weight. Therefore, thein-situ measurement of gas molecular weight in the downhole environmentdescribed herein will identify the naturally occurring hydrocarbon gasreservoirs and predict phase behavior of the formation fluid. Forexample, a CH₄ or C₁ dominated natural gas production well may have anaveraged molecular weight of equal and greater than 16 g/mol, but anyadditional C₂-C₅, N₂, and CO₂ could increase the measured molecularweight in a small amount, but averaged gas molecular weight could be anindicator of the gas reservoir composition stability.

As described in further detail below, the measured hydrocarbon gasmolecular weight provides a direct correlation to the gas composition ofthe formation fluid, which in conventional approaches is normallyobtained by time-consuming offline gas chromatography analysis. Throughuse of embodiments of the present disclosure, however, analysis of fluidcomposition may be conducted in real-time to thereby provide immediateanalysis of the hydrocarbon gas composition. As a result, downholesampling tools, such as the Halliburton RDTTM, will have added servicecapability for use in both crude oil and hydrocarbon gas reservoirs.

FIG. 1A is a high-level block diagrammatical illustration of a thermalmodulated vibrating tube based gas molecular weight sensing module 100according to certain illustrative embodiments of the present disclosure.Sensing module 100 includes first gas sensor 102 and second gas sensor104, which are connected to one another in series fashion. First andsecond sensors 102 and 104 are operated under isothermal temperatures T₁and T₂, respectively, as will be described in more detail below. In thisillustrative embodiment, sensing module 100 is attached to various flowcontrol mechanisms via a front flow line 106 a and back flow line 106 b.As shown, a pressure gauge 108 a, gas flow inlet control valve 110 a,pressure and flow regulator 112 a and a coalesce filter 114 are coupledin series fashion along front flow line 106 a.

During operation, coalesce filter 114 performs gas purification byblocking debris and solid particles, and minimizing erosions to chokes,flow lines, control valves, and other sensor packages. In some cases,the coalesced water droplets are repelled by hydrophobic barrier layers.In another case, a separator filter with a two-stage vertical coalescerand separator housing will be used to separate gas from hydrocarbonliquid. For practical application, a microporous film produced fromultra-high molecular weight polyethylene (“UHMW”) or low-density porousPTFE filters could be used in high-temperature (up to 500° F.) forventing of the gases while holding oil, liquid and water separation. Ina more practical operation, a controlled operation temperature andpressure could render the formation fluid in the pure gas phase from itsphase diagram. Connected in series along back flow line 106 b is anotherpressure gauge 108 b, gas flow outlet 110 b, and a back pressure andflow regulator 112 b, all used to maintain differential pressure andconstant flow stability through sensing module 100.

Front and back flow lines 106 a,b are in fluid communication with asource of wellbore formation fluid. In those examples in which sensingmodule 100 is used as a standalone device (e.g., in a laboratorysetting), lines 106 a,b may couple to gas supply pipeline. In thoseembodiments in which sensing module 100 was used in a downholeenvironment as part of a sampling tool, flow lines 106 a,b would beconnected to a downhole tool flow control unit in which to receivewellbore formation fluids under a constant differential pressure. Thoseordinarily skilled in the art having the benefit of this disclosurereadily understand there are a variety of ways in which to coupled flowlines 106 a,b.

FIG. 1B is an expanded view of a single gas sensor 102,104, according tocertain illustrative embodiments of the present disclosure. Gas sensor102,104 includes a hollow tube body 116 having a first end 116 a andsecond end 116 b. A venturi inlet 118 a is positioned at first end 116a, and a venturi outlet 118 b is positioned at second end 116 b. Avibrating tube 120 is fluidly coupled between venturi inlet 118 a andoutlet 118 b. Vibrating tube 120 is a tube through which wellboreformation fluid flows during operation of sensing module 100. Vibratingtube 120 may be made of high-strength titanium (Ti) metal, Ti-alloy,carbon fiber reinforced polymer composites (such as PPS and PEEK), witha typical length of 4-10″ and diameter of 0.1-0.4″. In most of cases,these tubing materials will work under 400° F. and 25 kpsi downholeconditions.

Venturi inlet/outlet 118 a,b allows control of fluid uniformity andpressure through the gas sensors 102,104. Specifically, when using arelative long tube for increasing the sensor gas sensitivity, thelimited gas flowing rate may affect the density and gas molecular weightmeasurement accuracy if the sensing tube only is not fully filled. Thelarge ratio of the external/internal tube diameters will enable the gasflow rate increase and thereby increase measurement accuracy.

A vibrational mechanism 122 is positioned on vibrating tube 120 toexcite tube 120 into vibration. In certain illustrative embodiments,vibrational mechanism 122 may be a magnet or coil assembly coupled toprocessing circuitry (not shown) via line A whereby excitation signalsare communicated. Vibrational mechanism 122 may also be utilized forsignal pickup/acquisition via line B, whereby vibrational measurements(e.g., resonant frequency, gas density, temperature, pressuremeasurements) are communicated to the processing circuitry.

Still referring to FIG. 1B, inlet flow line 106 a has a size of φ_(ft),and the gas flow from line 106 a to vibrating tube 120 has a size ofφ_(vt), where φ_(ft)>φ_(vt). Such flow tube different sizes result in aventuri operating mode whereby the higher temperature operationsurrounding the vibrating tube ensures the formation fluid is in asingle gaseous phase. In this example, gas sensor 102,104 also includesa temperature control loop feedback mechanism 124 coupled to atemperature sensor 126 positioned inside the cavity of hollow body 116.Feedback mechanism 124 may be, for example, aproportional-integral-derivative (“PID”) controller, based on eitherPRT100 or RTD, which is utilized to maintain gas sensor 102,104, andthus sensing module 100, in an isothermal condition.

A heating element (not shown) is embedded into a layer of the body ofhollow tube 116 to thereby maintain the desired temperature of gassensor 102,104. Another temperature sensor 128 is embedded into theheating element and connected to a thermometer 130, which is controlledand coupled to control loop feedback mechanism 124. Although not shown,feedback mechanism 124 is also coupled to processing circuitry. Via theuse of sensors 126 and 128, the temperature of gas sensor 102,104 may bemonitored and controlled.

As previously described, vibrational excitation mechanism 122 isattached to the surface of vibrating tube 120 for excitation and signalpick up. The front and rear fluid pressures and temperatures (P_(Inlet),T_(Inlet), P_(Outlet), T_(Outlet)) of the formation fluid can bemeasured before and after gas flow through gas sensor 102,104 viatemperature/pressure sensors (not shown). As will be described in moredetail below, the density variation of the wellbore formation fluid willbe measured through use of the venturi vibrating tube resonant frequencyshift between the first and second sensors (FIG. 1A), accompanied by thesimultaneous measurement of the inlet and outlet temperature (T_(Inlet),T_(Outlet)) and pressure (P_(Inlet), P_(Outlet)).

With reference back to the illustrative embodiment of FIG. 1A, gassensing module 100 consist of a pair of isothermal feedback controlledvibrating tube-based sensors 102,104, with first sensor 102 operated attemperature T_(i), and second sensor 104 operated at T₂. FIGS. 2A and 2Bare alternative illustrative embodiments of gas sensing module 100 inwhich sensors 102,104 are deployed in series configuration (FIG. 2A) andparallel configuration (FIG. 2B). In FIG. 2A, first and second gassensors 102a,b are connected to one another in series fashion wherebyventuri outlet 118 b of first sensor 102 is connected to venturi inlet118 a of second sensor 104. During an illustrative operation of gassensing module 200S of FIG. 2A, wellbore formation gas fluid flowsthrough sensor 102 that has an operating temperature at T₁, then, theformation fluid passes through second gas sensor 104 that has a higheroperating temperature at T₂. As a result of the vibration of tube 120,first and second sensors 102,104 will show first and second resonantfrequencies:

f(ρ₁ , T ₁)=f ₁(To)+a*T ₁ +b*ρ ₁, and f(ρ₂ , T ₂)=₂(To)+a*T ₂ +b*ρ ₂  Eq (1),

where f is frequency, ρ is gas density, T is sensor operationtemperature, and f₁(To)=f₂(To). The relative frequency differentiationbetween gas sensors 102 and 104 is approximately expressed as:

Δf(ρ)=f(ρ₁ , T ₁)−f(ρ₂ , T ₂)=a*(T ₁ −T ₂)+b*(ρ₁−ρ₂)≈f(ΔT)+b*Δρ   Eq(2),

where a and b are calibration constants at pre-set T₁ and T₂ with aknown gas density or molecular weight. For each individual sensor 102 or104, the gas molecular weight (MW) is approximately described by:

MW≈R·T*ρ/(z·P), with T ₁ /T ₂=ρ₂/ρ₁,    Eq. (3),

where z is 1 for ideal gas, but deviates from 1 for non-ideal gasmixtures.

For a constant gas mixture composition, the density difference will beproportional to relative gas molecular weight (MW) change, namely,

Δρ≈(z·P/R·T)·ΔMW   Eq. (4).

In such an operational mode, each gas sensor may provide measured gasmolecular weight, and the differential signal of the two gas molecularweights may be directly used for production quality monitoring asindicated by Eq. (4), where gas composition variation could varymeasured gas density difference.

In FIG. 2B, gas sensing module 100P includes first and second gassensors 102,104 arranged in a parallel configuration relative to oneanother. In this embodiment, inlet flow line 106 a is a flow splitterthat divides the wellbore formation fluid in a percentage of 0-100%, forexample, between first gas sensor 102 and second gas sensor 104, wherebythe fluid is then communicated onto venturi inlets 118 a of first andsecond gas sensors 102,104. After the formation fluid has traversedfirst and second gas sensors 102,104, it is then recombined at outletflow line 106 b (which is coupled to venturi outlets 118 b of sensors102,104). In an illustrative operation mode, the flow splitting ratio is0 or 100%, where the gas flows through only one of the gas sensors atone time if the flow is controlled by an automatic switch valve.

To prevent gas backflow or interference from outlet flow line 106 b, asolenoid valve (not shown) should be used. For wet or saturated gasanalysis, the gas sensing module 100P may require a filter for gas andliquid separation in the front of flowline 106 a. Such a filter could bea coalesce or centrifugal-based filter that can separate heavy liquidfrom wet gas stream and thereby allow the gas phase to flow past sensor102, 104. For example, a microporous film produced from UHMWpolyethylene or lo-density porous PTFE filters could be used inhigh-temperatures (up to 500° F., for example) for venting of the gaseswhile maintaining oil, liquid and water separation. However, theseparated hydrocarbon liquid will be forced to pass through the othergas sensor (second sensor 104 in FIG. 2B), while the gas phase will passthrough the sensor (first gas sensor 102). In such configurations, whenboth gas sensors are operated under the same operating temperature, themeasured gas molecular weight difference will indicate potential wet gasor saturated gas flows by setting T₁=T₂ in Eq. (1)

The results from the differential measurement from Eq. (2) should beclose to zero. Otherwise, the potential wet gas or saturated gas mayexist when the surrounding environment is kept constant in bothtemperature and pressure.

Now that the an overview of the mathematical theory has been given inEquations 1-4, a more detail description of the method by which gasmolecular weight is calculated will now be described. In certainmethods, gas molecular analysis starts by measuring the wellboreformation fluid (e.g., multi-component hydrocarbon gas mass) using firstand second gas sensors 102,104 to thereby determine a first and secondgas density using:

ρ_(1,2)(T, f)=ρ(0)+ξ*Y(T)/(f(T)*L)²    Eq (5),

where Y(T)=Y(0)+c*T+d*T²+ . . . is the temperature dependent Youngmodulus of vibrating tube 120 with c and d as constants, L is the lengthof the vibrating tube, and ξ is the calibration parameter. In certainembodiments, the natural vibrational frequency range of tube 120 is froma few hundred Hz to 20 kHz.

Therefore, for dry gas, the gas molecular weight, under an ideal case,can be expressed as in terms of gas density as:

ρ₁=ρ(0)+(MW)*z·P ₁ /RT ₁    Eq (6), and

ρ₂=ρ(0)+(MW)*z·P ₂ /RT ₂    Eq (7),

Where ρ₁ is the first gas density, ρ₂ is the second gas density, R isthe universal gas constant, and P₁ and P₂ are the pressures insidevibrating tubes 120, and ρ(0) is the sensor calibration constant atT(0). The differentiation of the two gas densities ρ₁ and ρ₂ is:

Δρ(T ₁ , T ₂)=(MW)*(P ₁ /T ₁ −P ₂ /T ₂)/R    Eq (8), or

MW=(ρ₁−ρ₂)*R/(P ₁ /T ₁ −P ₂ /T ₂).    Eq (9).

In an alternate method, for dry hydrocarbon gas analysis, two vibratingtube operation temperatures T₁ and T₂ are preset, along with thefeedback control mechanism 124 to thereby maintain isothermal statusoperation. When the flowline inlet (106 a) pressure P is known, thepressure (P₁, P₂) inside vibrating tubes 120 can be calculated by:

ΔP(P−P _(i))=1/2*ρ*(υ₂ ²−υ₁ ²), i=1 and 2    Eq (10)

where ρ is the fluid density, υ₁ and υ₂ are flow velocities before gasflowing into the gas sensors 102,104 and inside vibrating tube 120,respectively. For high-accuracy measurement, both T₁ and T₂ should berelative higher than the downhole formation fluid temperature. Themeasured gas molecular weight is more or less insensitive to sensingmodule thermal drifting effects by:

1/(T ₁ +ΔT)−1/(T ₂ +ΔT)≈1/T ₁−1/T ₂, where ΔT<<T ₁ and T₂    Eq (11),

where gas sensors 102,104 have the same venturi structure (e.g., length,material, etc.) and internal tube pressures P₁=P₂. On the other hand,the gas flow rate along the flowline 106 is another factor which couldlead to gas stream temperature variation. To combat this, feedbackmechanism 124 maintains the sensing module in isothermal condition,which greatly mitigates the effects of thermal drift under downholeconditions. Such an isothermal package is critical especially thedownhole logging tool is working along wellbore at different depths ortemperature zones.

In yet another method, for wet and saturated hydrocarbon gas analysis,the pre-set temperature T₁ can be the maximum of the downhole formationfluid temperature, but T₂ may be preset as high as allowed (based upontool design), such as, for example, from 350° F. (177° C.) to 800° F.(427° C.). As a result, most of the “wet gas” or gas mixed with somelow-density mixture of hydrocarbon liquid can be flushed as vapors if T₂is greater than the liquid boiling point. FIGS. 3A and 3B are plotsshowing hydrocarbon boiling points and molecular weight as a function ofthe carbon number, respectively. Thus, in this illustrative method,FIGS. 3A and 3B may be used as a reference to set the T₂ value. As canbe seen in the graphs, for hydrocarbon formation fluid with a carbonnumber up to 20, the boiling point is about 300° C.; however, theboiling point will be about 440° C. for carbon number up to 30. Thus,the corresponding gas molecular weight can change more than 100 g/mol.In this method, the following may be utilized to calculate molecularweight:

MW=[ρ ₂(gas)−ρ(0)]*R*T ₂ /ΔP    Eq (12).

In yet another illustrative method of the present disclosure, to controlthe fluid phase during wet and saturated hydrocarbon gas analysis, thevibrating tube operational temperature (T₁, T₂), inlet pressureP_(inlet), (shown in FIGS. 1B, 2A and 2B), and differential pressure ΔPmay be pre-set to the proper operating point based upon thepressure-temperature (“PT”) phase diagram, as shown in FIG. 4. In mostcases, by using an operation temperature higher than a thresholdtemperature (T>T_(th)) that is outside the two-phase regime or dew-pointcurve, the formation fluid will be driven to the gas phase, asrepresented by the dashed vertical line in FIG. 4. In addition, theconfiguration of gas sensors 102,104 may be utilized to reduce the gaspressure inside vibrating tube 120 by using a ΔP that shifts theoperation point outside the two-phase region of FIG. 4 to therebyachieve single gas phase operation.

However, when the operating temperature of the sensing module ismaintained below T_(th), the flowline inlet pressure P may be set higherthan the operation point of FIG. 4 to thereby force gas phase operationthat can turn two-phase formation fluid into single-phase gas flow. Forthis purpose, temperature feedback mechanism 124 is provided and fluidline differential pressure may be also adjusted as necessary.

Furthermore, in yet other illustrative methods, note that under anon-ideal gas situation where z≠1, the multi-component hydrocarbon gasmolecular weight should be analyzed by:

MW≈(ρ₁−ρ₂)*V*(V+b′)*R*(1/T ₁ ^(1.5)−1/T ₂ ^(1.5))/a′   Eq (13),

where a′ (0.4278*R²*T_(c) ^(2.5)/P_(c)) and b′ (0.0867*R*T_(c)/P_(c))are van der Waals constants, defined by the Redlich-Kwong equation atcritical temperature, T_(c), and critical pressure P_(c); V can be takenas gas mole volume. The measured gas molecular weight could be used todetermine whether the formation fluid composition is dry, wet orsaturated gas. Eq. (13) can be used for interpreting the field measureddata from Eq. (12) with EOS based PVT modeling and simulation.

In another illustrative method, the measured gas molecular weight can beused to calculate EOS for identifying the naturally occurringhydrocarbon gas reservoirs and to predict possible phase behavior of theformation fluid, as shown in FIG. 5 using a simulation based on 97% C1(CH₄, Methane, MW=16.04 g/cm³), and 2% C2 (C₂H₆, Ethane, MW=30.07 g/cm³)with 0.82% C7+ hydrocarbons. FIG. 5 illustrates the PT phase envelopunder three different gas molecular weights. In reality, 0.87% C7+ mayhave different molecular weights, such as from 90 to a few hundredsg/cm³, for example. In one case, a gas reservoir may consist primarilyof C1-C4 hydrocarbon gas, but the 0.82% C7+ may have an averagedmolecular weight of 97 g/cm³. In another case, the 0.82% C7+ may have anaveraged molecular weight of 110 g/cm³, while in another case, the 0.82%C7+ may have an averaged molecular weight of 130 g/cm³. Although theaverage gas molecular weight only changes from 18.293, 18.402, to 18.566g/cm³ in this example, the PT phase envelop diagram, as shown in FIG. 5,has changed dramatically.

In FIG. 5, it is clear that the high carbon bonded hydrocarbons ofC7-C30 may have limited content as wet gas, which is saturated with ˜1%volume of liquid hydrocarbons, but the gas molecular weight increasecould indicate the corresponding PT phase envelop change, which may havea high impact on the well completion design or asset management. Themeasurement of the average gas molecular weight also can help tounderstand the transport properties of hydrocarbons through differentlayers of the subsurface formation. In one example, the increase of thewater will decrease measured average gas molecular weight. In anotherexample, because of localized geothermal anomalies, the heavy oilevaporated gas could increase averaged gas molecular weight. In yetanother example, carbon dioxide may become rich due to specificgeological regions that also increase the measured averaged gasmolecular weight. These hydrocarbon gas composition changes will modifya well's PT phase envelop diagram. Accordingly, the simulation describedhere shows that the critical point and gas/liquid due-point curve can bechanged by an increase a small amount of the gas molecular weight.

As previously mentioned, wet gas detection is a particularly importantconcept in the field of flow measurement, as the varying densities ofthe constituent materials present a significant problem. Usingembodiments of the present disclosure, the gas molecular weightmeasurements provide a new method by which to evaluate downholeformation fluid properties. In certain embodiments, the gas sensormodules may be deployed with an existing RDT sampling tool afterintegration, or as part of a downhole assembly such as, for example, anindependent service of logging-while-drilling (“LWD”) ormeasurement-while-drilling (“MWD”).

In certain embodiments, the methods described above may be performed byprocessing circuitry onboard a gas sensing module or located at someremote location. In either case, such processing circuitry wouldcomprises a signal processor, communications module and other circuitrynecessary to achieve the objectives of the present disclosure, as willbe understood by those ordinarily skilled in the art having the benefitof this disclosure. In addition, it will also be recognized that thesoftware instructions necessary to carry out the objectives of thepresent disclosure may be stored within storage located within theprocessing circuitry or loaded into that storage from a CD-ROM or otherappropriate storage media via wired or wireless methods. Such softwareand processing circuitry will enable the processing of high-volume dataand interpretation/correlation of the vibrational measurementtime-domain data to gas molecular weight based on the vibrationalresonant frequencies. If the processing circuitry is remotely located, asuitable wired or wireless communications link may provide a medium ofcommunication between the processing circuitry and the sensing module.Alternatively, however, the communications link may be anelectromagnetic device of suitable frequency, or other methods includingacoustic communication and like devices.

FIG. 6 illustrates an embodiment of the present disclosure whereby a gasmolecular weight sensing module is utilized in a wireline application.Here, a sampling tool 600 includes a sensing module as described herein,and is shown positioned along wellbore 604. Sampling tool 600 has beensuspended along formation layers 606 by a cable 602 having conductorsfor transporting power to sampling tool 600 and telemetry to/fromsampling tool 600 and the surface. In such a deployment, the samplingtool 600 is utilized for formation fluid sampling and the inlet flowline (not shown) will provide pumpout service first to the gas sensingmodule. Once the formation fluid has been received, the gas sensingmodule acquires the vibrational measurements utilized to determine thegas molecular weight in-situ as described herein. The vibrationalmeasurement signals could be saved to a memory disk onboard samplingtool 600 and processed in-situ using circuitry onboard tool 600, ortransmitted to the surface via cable 602 for well site processing. Alogging facility 608 collects measurements from sampling tool 600, andmay include circuitry 610 for processing and storing the measurementsreceived from the sensing module of tool 600.

The gas molecular weight sensing modules described herein provide anumber of advantages. First, for example, the venturi design andvibrating tube provides highly-sensitive gas molecular weight analysisthat solves low gas sensitivity issues suffered by conventional tools.Second, use of the venturi design allows removal desired quantities oflow-density hydrocarbon liquid mixtures via manipulation of the pressureand temperature. Third, the ability to pre-set differential operatingtemperatures of the gas sensors mitigates thermal-drifting and therebyalleviates the need for much of the maintenance and calibrationnecessary with conventional tools. Fourth, the gas sensing modules maybe utilized in a variety of applications, such as, for example, openholewireline logging or drilling services, or for permanent gas wellproduction control and optimization.

Embodiments and methods described herein further relate to any one ormore of the following paragraphs:

1. A method to determine gas molecular weight of wellbore formationfluid, the method comprising receiving wellbore formation fluid into asensing module comprising a first sensor comprising a tube and a secondsensor comprising a tube; vibrating the tubes of the first and secondsensors; communicating the wellbore formation fluid through the firstand second vibrating tubes; acquiring vibrational measurements of thewellbore formation fluid flowing through the vibrating tubes; andutilizing the vibrational measurements to determine the gas molecularweight of the wellbore formation fluid.

2. A method as defined in paragraph 1, wherein acquiring the vibrationalmeasurements comprises acquiring a first resonant frequency of thevibrating tube of the first sensor as the wellbore formation fluid flowstherethrough; acquiring a second resonant frequency of the vibratingtube of the second sensor as the wellbore fluid flows therethrough;acquiring temperature and pressure measurements of the wellboreformation fluid; and utilizing a differentiation between the first andsecond resonant frequencies to determine a gas density measurement ofthe wellbore formation fluid.

3. A method as defined in paragraph 1 or 2, wherein the gas density,temperature, and pressure measurements of the wellbore formation fluidare acquired simultaneously.

4. A method as defined in any of paragraphs 1-3, further comprisingmaintaining the first and second sensors under an isothermal condition.

5. A method as defined in any of paragraphs 1-4, wherein the first andsecond sensors are maintained at a same temperature.

6. A method as defined in any of paragraphs 1-5, wherein the first andsecond temperatures are maintained at different temperatures.

7. A method as defined in any of paragraphs 1-6, wherein vibrating thetubes comprises activating an excitation mechanism positioned on thetubes.

8. A method as defined in any of paragraphs 1-7, further comprisingutilizing the gas molecular weight to identify the wellbore formationfluid.

9. A method as defined in any of paragraphs 1-8, further comprisingutilizing the gas molecular weight to predict phase behavior of thewellbore formation fluid.

10. A method as defined in any of paragraphs 1-9, wherein the sensingmodule is deployed into a wellbore.

11. A method as defined in any of paragraphs 1-10, wherein the gasmolecular weight of the wellbore formation fluid is determined in-situ.

12. A method to determine gas molecular weight of wellbore formationfluid, the method comprising receiving a wellbore formation fluid into asensing module comprising a tube; vibrating the tube; communicating thewellbore formation fluid into the vibrating tube; acquiring vibrationalmeasurements of the wellbore fluid flowing through the vibrating tube;and utilizing the vibrational measurements to determine the gasmolecular weight of the wellbore fluid.

13. A method as defined in paragraph 12, wherein acquiring thevibrational measurements comprises simultaneously acquiring a gasdensity measurement, temperature measurement, and pressure measurementof the wellbore fluid.

14. A method as defined in paragraphs 12 or 13, further comprisingmaintaining the sensing module under an isothermal condition with anoperation temperature maximum allowed by a downhole logging servicetool.

15. A method as defined in any of paragraphs 12-14, wherein vibratingthe tube comprises activating an excitation mechanism positioned on thetube.

16. A method as defined in any of paragraphs 12-15, further comprisingutilizing the gas molecular weight to identify the wellbore formationfluid.

17. A method as defined in any of paragraphs 12-16, further comprisingutilizing the gas molecular weight to predict phase behavior of thewellbore fluid.

18. A method as defined in any of paragraphs 12-17, wherein the sensingmodule comprises a first and second gas sensor, each of the first andsecond gas sensors comprising a tube; vibrating the tube comprisesvibrating the tubes of the first and second sensors; communicating thewellbore fluid into the vibrating tube comprises: communicating thewellbore formation fluid into the vibrating tube of the first sensor;and communicating the wellbore formation fluid into the vibrating tubeof the second sensor; acquiring vibrational measurements of the wellborefluid comprises: acquiring temperature and pressure measurements of thewellbore fluid traveling through the vibrating tube of the first sensor;acquiring a first gas density measurement of the wellbore fluidtraveling through the vibrating tube of the first sensor; acquiringtemperature and pressure measurements of the wellbore fluid travelingthrough the vibrating tube of the second sensor; and acquiring a secondgas density measurement of the wellbore fluid traveling through thevibrating tube of the second sensor; and determining the gas molecularweight of the wellbore fluid is achieved using a differentiation of thefirst and second gas density measurements.

19. A method as defined in any of paragraphs 12-18, wherein: the sensingmodule comprises a first and second gas sensor arranged in seriesconfiguration with relation to one another, the first and second sensorseach comprising a tube; vibrating the tube comprises vibrating the tubesof the first and second sensors; communicating the wellbore formationfluid into the vibrating tube comprises: communicating the wellboreformation fluid into the vibrating tube of the first sensor; andcommunicating the wellbore formation fluid into the vibrating tube ofthe second sensor; acquiring vibrational measurements of the wellboreformation fluid comprises: acquiring inlet temperature and pressuremeasurements of the wellbore fluid entering the first sensor; acquiringa first gas density measurement of the wellbore fluid as the wellborefluid travels through the vibrating tube of the first sensor; acquiringa second gas density measurement of the wellbore fluid as the wellborefluid travels through the vibrating tube of the second sensor; andacquiring outlet temperature and pressure measurements of the wellboreformation fluid exiting the second sensor; and determining the gasmolecular weight of the wellbore formation fluid is achieved using adifferentiation of the first and second gas density measurements.

20. A method as defined in any of paragraphs 12-19, wherein: the sensingmodule comprises a first and second sensor arranged in parallelconfiguration with relation to one another, the first and second sensorseach comprising a tube; vibrating the tube comprises vibrating the tubesof the first and second sensors; communicating the wellbore formationfluid into the vibrating tube comprises: communicating the wellborefluid into the vibrating tube of the first sensor; and communicating thewellbore formation fluid into the vibrating tube of the second sensor;acquiring vibrational measurements of the wellbore formation fluidcomprises: acquiring inlet temperature and pressure measurements of thewellbore formation fluid entering the first sensor; acquiring inlettemperature and pressure measurements of the wellbore formation fluidentering the second sensor; acquiring a first gas density measurement ofthe wellbore formation fluid as the wellbore formation fluid flowsthrough the vibrating tube of the first sensor; acquiring a second gasdensity measurement of the wellbore formation fluid as the wellborefluid flows through the vibrating tube of the second sensor; acquiringoutlet temperature and pressure measurements of the wellbore fluidexiting the first sensor; and acquiring outlet temperature and pressuremeasurements of the wellbore fluid exiting the second sensor; anddetermining the gas molecular weight of the wellbore formation fluid isachieved using a differentiation of the first and second gas densitymeasurements.

21. A method as defined in any of paragraphs 12-20, wherein the sensingmodule is deployed into a wellbore.

22. A method as defined in any of paragraphs 12-21, whereincommunicating the wellbore formation fluid into the vibrating tubecomprises utilizing a coalesce filter to remove particles from thewellbore formation fluid before communicating the wellbore formationfluid into the vibrating tube.

23. A method as defined in any of paragraphs 12-22, communicating thewellbore formation fluid into the vibrating tube comprises utilizing alow-density PTFE or high-density polyethylene filter to separategas/liquid phases of the wellbore formation fluid before communicatingthe wellbore formation fluid into the vibrating tube.

24. A sensing module to determine gas molecular weight of wellboreformation fluid, the sensing module comprising: a first sensorcomprising a vibrating tube through which wellbore formation fluid mayflow; and a vibrational excitation mechanism positioned on the tube; anda second sensor comprising a vibrating tube through which wellbore fluidmay flow; and a vibrational excitation mechanism positioned on the tube.

25. A sensing module as defined in paragraph 24, wherein the first andsecond sensors each comprise a hollow tube body having first and secondends; a venturi inlet positioned at the first end; and a venturi outletpositioned at the second end, wherein the vibrating tube is coupledbetween the venturi inlet and outlet.

26. A sensing module as defined in paragraphs 24 or 25, wherein thehollow tube body comprises a heating element.

27. A sensing module as defined in any of paragraphs 24-26, furthercomprising: a first temperature sensor embedded within the heatingelement; and a second temperature sensor positioned inside the hollowtube body.

28. A sensing module as defined in any of paragraphs 24-27, wherein thesecond temperature sensor comprises part of a temperature control loopfeedback mechanism.

29. A sensing module as defined in any of paragraphs 24-28, furthercomprising processing circuitry operationally coupled to the vibrationalexcitation mechanism to thereby communicate electrical signalstherebetween.

30. A sensing module as defined in any of paragraphs 24-29, wherein thevibrational excitation mechanism is at least one of a magnetic assemblyor coil assembly.

31. A sensing module as defined in any of paragraphs 24-30, wherein thefirst and second sensors are arranged in series configuration relativeto one another.

32. A sensing module as defined in any of paragraphs 24-31, wherein thesensing module further comprises a flow inlet coupled to the venturiinlet of the first sensor; and a flow outlet coupled to the venturioutlet of the second sensor.

33. A sensing module as defined in any of paragraphs 24-32, wherein thefirst and second sensors are arranged in parallel configuration relativeto one another.

34. A sensing module as defined in any of paragraphs 24-33, wherein thesensing module further comprises a flow inlet coupled to the venturiinlets of the first and second sensors; and a flow outlet coupled to theventuri outlets of the first and second sensors.

35. A sensing module as defined in any of paragraphs 24-34, furthercomprising a coalesce or polymer filter coupled to a flow inlet of thesensing module; and a pressure and flow control mechanism coupled to theflow inlet and a flow outlet of the sensing module.

36. A sensing module as defined in any of paragraphs 24-35, wherein thesensing module forms part of a downhole assembly.

37. A sensing module as defined in any of paragraphs 24-36, wherein thevibrating tubes of the first and second sensors comprises a Ti orTi-alloy, or a carbon fiber reinforced polymer composite material basedhigh-strength tube.

Although various embodiments and methodologies have been shown anddescribed, the disclosure is not limited to such embodiments andmethodologies and will be understood to include all modifications andvariations as would be apparent to one skilled in the art. Therefore, itshould be understood that embodiments of the disclosure are not intendedto be limited to the particular forms disclosed. Rather, the intentionis to cover all modifications, equivalents and alternatives fallingwithin the spirit and scope of the disclosure as defined by the appendedclaims.

What is claimed is:
 1. A method to determine gas molecular weight ofwellbore formation fluid, the method comprising: receiving wellboreformation fluid into a sensing module comprising: a first sensorcomprising a tube; and a second sensor comprising a tube; vibrating thetubes of the first and second sensors; communicating the wellboreformation fluid through the first and second vibrating tubes; acquiringvibrational measurements of the wellbore formation fluid flowing throughthe vibrating tubes; and utilizing the vibrational measurements todetermine the gas molecular weight of the wellbore formation fluid.
 2. Amethod as defined in claim 1, wherein acquiring the vibrationalmeasurements comprises: acquiring a first resonant frequency of thevibrating tube of the first sensor as the wellbore formation fluid flowstherethrough; acquiring a second resonant frequency of the vibratingtube of the second sensor as the wellbore fluid flows therethrough;acquiring temperature and pressure measurements of the wellboreformation fluid; and utilizing a differentiation between the first andsecond resonant frequencies to determine a gas density measurement ofthe wellbore formation fluid.
 3. A method as defined in claim 2, whereinthe gas density, temperature, and pressure measurements of the wellboreformation fluid are acquired simultaneously.
 4. A method as defined inclaim 1, further comprising maintaining the first and second sensorsunder an isothermal condition.
 5. A method as defined in claim 1,wherein the first and second sensors are maintained at a sametemperature.
 6. A method as defined in claim 1, wherein the first andsecond temperatures are maintained at different temperatures.
 7. Amethod as defined in claim 1, wherein vibrating the tubes comprisesactivating an excitation mechanism positioned on the tubes.
 8. A methodas defined in claim 1, further comprising utilizing the gas molecularweight to identify the wellbore formation fluid.
 9. A method as definedin claim 1, further comprising utilizing the gas molecular weight topredict phase behavior of the wellbore formation fluid.
 10. A method asdefined in claim 1, wherein the sensing module is deployed into awellbore.
 11. A method as defined in claim 10, wherein the gas molecularweight of the wellbore formation fluid is determined in-situ.
 12. Amethod to determine gas molecular weight of wellbore formation fluid,the method comprising: receiving a wellbore formation fluid into asensing module comprising a tube; vibrating the tube; communicating thewellbore formation fluid into the vibrating tube; acquiring vibrationalmeasurements of the wellbore fluid flowing through the vibrating tube;and utilizing the vibrational measurements to determine the gasmolecular weight of the wellbore fluid.
 13. A method as defined in claim12, wherein acquiring the vibrational measurements comprisessimultaneously acquiring a gas density measurement, temperaturemeasurement, and pressure measurement of the wellbore fluid.
 14. Amethod as defined in claim 13, further comprising maintaining thesensing module under an isothermal condition with an operationtemperature maximum allowed by a downhole logging service tool.
 15. Amethod as defined in claim 12, wherein vibrating the tube comprisesactivating an excitation mechanism positioned on the tube.
 16. A methodas defined in claim 12, further comprising utilizing the gas molecularweight to identify the wellbore formation fluid.
 17. A method as definedin claim 12, further comprising utilizing the gas molecular weight topredict phase behavior of the wellbore fluid.
 18. A method as defined inclaim 12, wherein: the sensing module comprises a first and second gassensor, each of the first and second gas sensors comprising a tube;vibrating the tube comprises vibrating the tubes of the first and secondsensors; communicating the wellbore fluid into the vibrating tubecomprises: communicating the wellbore formation fluid into the vibratingtube of the first sensor; and communicating the wellbore formation fluidinto the vibrating tube of the second sensor; acquiring vibrationalmeasurements of the wellbore fluid comprises: acquiring temperature andpressure measurements of the wellbore fluid traveling through thevibrating tube of the first sensor; acquiring a first gas densitymeasurement of the wellbore fluid traveling through the vibrating tubeof the first sensor; acquiring temperature and pressure measurements ofthe wellbore fluid traveling through the vibrating tube of the secondsensor; and acquiring a second gas density measurement of the wellborefluid traveling through the vibrating tube of the second sensor; anddetermining the gas molecular weight of the wellbore fluid is achievedusing a differentiation of the first and second gas densitymeasurements.
 19. A method as defined in claim 12, wherein: the sensingmodule comprises a first and second gas sensor arranged in seriesconfiguration with relation to one another, the first and second sensorseach comprising a tube; vibrating the tube comprises vibrating the tubesof the first and second sensors; communicating the wellbore formationfluid into the vibrating tube comprises: communicating the wellboreformation fluid into the vibrating tube of the first sensor; andcommunicating the wellbore formation fluid into the vibrating tube ofthe second sensor; acquiring vibrational measurements of the wellboreformation fluid comprises: acquiring inlet temperature and pressuremeasurements of the wellbore fluid entering the first sensor; acquiringa first gas density measurement of the wellbore fluid as the wellborefluid travels through the vibrating tube of the first sensor; acquiringa second gas density measurement of the wellbore fluid as the wellborefluid travels through the vibrating tube of the second sensor; andacquiring outlet temperature and pressure measurements of the wellboreformation fluid exiting the second sensor; and determining the gasmolecular weight of the wellbore formation fluid is achieved using adifferentiation of the first and second gas density measurements.
 20. Amethod as defined in claim 12, wherein: the sensing module comprises afirst and second sensor arranged in parallel configuration with relationto one another, the first and second sensors each comprising a tube;vibrating the tube comprises vibrating the tubes of the first and secondsensors; communicating the wellbore formation fluid into the vibratingtube comprises: communicating the wellbore fluid into the vibrating tubeof the first sensor; and communicating the wellbore formation fluid intothe vibrating tube of the second sensor; acquiring vibrationalmeasurements of the wellbore formation fluid comprises: acquiring inlettemperature and pressure measurements of the wellbore formation fluidentering the first sensor; acquiring inlet temperature and pressuremeasurements of the wellbore formation fluid entering the second sensor;acquiring a first gas density measurement of the wellbore formationfluid as the wellbore formation fluid flows through the vibrating tubeof the first sensor; acquiring a second gas density measurement of thewellbore formation fluid as the wellbore fluid flows through thevibrating tube of the second sensor; acquiring outlet temperature andpressure measurements of the wellbore fluid exiting the first sensor;and acquiring outlet temperature and pressure measurements of thewellbore fluid exiting the second sensor; and determining the gasmolecular weight of the wellbore formation fluid is achieved using adifferentiation of the first and second gas density measurements.
 21. Amethod as defined in claim 12, wherein the sensing module is deployedinto a wellbore.
 22. A method as defined in claim 12, whereincommunicating the wellbore formation fluid into the vibrating tubecomprises utilizing a coalesce filter to remove particles from thewellbore formation fluid before communicating the wellbore formationfluid into the vibrating tube.
 23. A method as defined in claim 12,communicating the wellbore formation fluid into the vibrating tubecomprises utilizing a low-density PTFE or high-density polyethylenefilter to separate gas/liquid phases of the wellbore formation fluidbefore communicating the wellbore formation fluid into the vibratingtube.
 24. A sensing module to determine gas molecular weight of wellboreformation fluid, the sensing module comprising: a first sensorcomprising: a vibrating tube through which wellbore formation fluid mayflow; and a vibrational excitation mechanism positioned on the tube; anda second sensor comprising: a vibrating tube through which wellborefluid may flow; and a vibrational excitation mechanism positioned on thetube.
 25. A sensing module as defined in claim 24, wherein the first andsecond sensors each comprise: a hollow tube body having first and secondends; a venturi inlet positioned at the first end; and a venturi outletpositioned at the second end, wherein the vibrating tube is coupledbetween the venturi inlet and outlet.
 26. A sensing module as defined inclaim 25, wherein the hollow tube body comprises a heating element. 27.A sensing module as defined in claim 26, further comprising: is a firsttemperature sensor embedded within the heating element; and a secondtemperature sensor positioned inside the hollow tube body.
 28. A sensingmodule as defined in claim 26, wherein the second temperature sensorcomprises part of a temperature control loop feedback mechanism.
 29. Asensing module as defined in claim 24, further comprising processingcircuitry operationally coupled to the vibrational excitation mechanismto thereby communicate electrical signals therebetween.
 30. A sensingmodule as defined in claim 24, wherein the vibrational excitationmechanism is at least one of a magnetic assembly or coil assembly.
 31. Asensing module as defined in claim 24, wherein the first and secondsensors are arranged in series configuration relative to one another.32. A sensing module as defined in claim 31, wherein the sensing modulefurther comprises: a flow inlet coupled to the venturi inlet of thefirst sensor; and a flow outlet coupled to the venturi outlet of thesecond sensor.
 33. A sensing module as defined in claim 24, wherein thefirst and second sensors are arranged in parallel configuration relativeto one another.
 34. A sensing module as defined in claim 33, wherein thesensing module further comprises: a flow inlet coupled to the venturiinlets of the first and second sensors; and a flow outlet coupled to theventuri outlets of the first and second sensors.
 35. A sensing module asdefined in claim 24, further comprising: a coalesce or polymer filtercoupled to a flow inlet of the sensing module; and a pressure and flowcontrol mechanism coupled to the flow inlet and a flow outlet of thesensing module.
 36. A sensing module as defined in claim 24, wherein thesensing module forms part of a downhole assembly.
 37. A sensing moduleas defined in claim 24, wherein the vibrating tubes of the first andsecond sensors comprises a Ti or Ti-alloy, or a carbon fiber reinforcedpolymer composite material based high-strength tube.